Oil & Gas Glossary 1.0

A choke in which the orifice size must be changed to change the rate of flow through the choke.

A set of controls, usually placed on the rig floor, that is manipulated to control the amount of drilling fluid being circulated through the choke manifold. This procedure is necessary when a kick is being circulated out of a well. See choke manifold.

An arrangement of piping and special valves, called chokes. In drilling, mud is circulated through a choke manifold when the blowout preventers are closed. In well testing, a choke manifold attached to the wellhead allows flow and pressure control for test components downstream.

A device with a restricted opening placed in the lower end of the tubing to control the rate of flow. See choke.

A device placed in a choke line that regulates the flow through the choke. Flow depends on the size of the opening in the bean; the larger the opening, the greater the flow.

The valve on the choke and flow line that is nearest to the preventer assembly. Its purpose is to stop the flow through the choke and flow line.

An extension from the blowout preventer assembly used to direct control the flow of well fluids from the annulus to the choke.

A bottomhole choke run on wireline and landed in a nipple profile in the tubing string.

A pipe attached to the blowout preventer stack out of which kick fluids and mud can be pumped to the choke manifold when a blowout preventer is closed in on a kick.

1. a chemical that, when dissolved in water, dissociates into positive and negative ions, thus increasing its electrical conductivity. See dissociation.

A method of killing a well that has kicked, in which the choke size is adjusted to maintain a constant casing pressure. This method does not work unless the kick is all or nearly all salt water. if the kick is gas, this method will not maintain a constant bottomhole pressure, because gas expands as it rises in the annulus. In any case, it is not a recommended well-control procedure.

A cutout section in a cone enabling positive slip movement without the aid of conventional slip return springs

A permanent packer, drillable in nature, capable of withstanding extreme working pressures, for remedial work. It has a positive flow-control valve built in.

The curved upper surface of a liquid column, concave when the containing walls are wet by the liquid (negative meniscus) and convex when not (positive meniscus).

A storm choke

A tubing safety valve.

Abbreviation: choke-line friction pressure.

2. the pressure drop from the outer limits of drainage to the wellbore caused by the relatively thin veneer (or skin) of the affected formation. Skin is expressed in dimensionless units: a positive value denotes formation damage; a negative value indicate improvement. Also called skin effect.

A choke, used to regulate flow of fluid from a well. Different sizes of beans are used for different producing rates.

A device inserted in a flow line to regulate the rate of flow.

In well-control operations, closing the BOP's with the choke and HCR, or fail-safe, valves open. Compare hard shut-in.

A mechanical fluid-measuring device that measures by filling and emptying chambers of a specific volume. The displacement of a fixed volume of fluid may be accomplished by the action of reciprocating or oscillating pistons, rotating vanes or buckets, rotating disks, or tanks or other vessels that automatically fill and empty. Also called a volume meter or volumeter.

In a well-control operation, closing the BOP without first opening an alternate flow path up the choke line. When the BOP is closed, pressure in the annulus cannot be read on the casing pressure gauge.

See back-pressure

A fitting placed in the blowout preventer stack to provide space between preventers for facilitating stripping operations, to permit attachment of choke and kill lines, and for localizing possible erosion by fluid flow to the spool instead of to the more expensive pieces of equipment.

A well is considered "stabilized" when, in the case of a flowing well, the rate of production through a given size of choke remains constant, or, in the case of pumping well, when the fluid column within the well remains constant in height.

A method of killing a well in which the mud level in the pits is held constant while the choke size is reduced and the pump speed slowed. It is not effective, and therefore, is not recommended, because casing pressure increases to the point at which the formation fractures or casing ruptures, and control of the well is lost.